In pneumatic hammer or percussion drilling, rate of penetration (ROP) is achieved by impacting the end of the borehole with a reciprocating hammer bit, in contrast with conventional rotary bit drilling, where ROP is achieved by the shearing of material at the end of the borehole. Pneumatic hammer drilling can often result in a greater ROP than can be achieved by rotary bit drilling due to the relative efficiency with which the drilling energy can be delivered to the end of the borehole.
Typically, pneumatic hammer drilling involves rotating the hammer bit while it is reciprocating so that the impact elements of the hammer bit do not repeatedly impact upon the same location at the end of the borehole. Rotation of the hammer bit can be accomplished either by rotating the hammer bit together with the drilling assembly and the drill string (as in rotary drilling), or by rotating the hammer bit independently without rotating the drilling assembly and the drill string (as in sliding drilling). Rotary drilling is typically used in non-directional drilling where control over the orientation of the resulting borehole is not critical, while sliding drilling is typically used in directional drilling where control over the orientation of the resulting borehole is desirable.
Rotation of the hammer bit together with the drill string is typically accomplished by providing compatible splines, or an alternative positive connection, between the drill string or other components of the drilling assembly and the hammer bit such that rotation of the drill string, by a rotary table typically mounted on the rig platform, may be transferred to the hammer bit. While rotating, the hammer bit is also reciprocated by the pneumatic hammer to impact the end of the borehole.
For example, a pneumatic hammer used for rotary drilling is described in U.S. Pat. No. 4,163,478 issued Aug. 7, 1979 to Adcock, U.S. Pat. No. 4,530,408 issued Jul. 23, 1985 to Toutant, U.S. Pat. No. 4,919,221 issued Apr. 24, 1990 to Pascale, U.S. Pat. No. 4,962,822 issued Oct. 16, 1990 to Pascale, U.S. Pat. No. 5,205,363 issued Apr. 27, 1993 to Pascale and U.S. Pat. No. 5,564,510 issued Oct. 15, 1996 to Walter.
As described in the above noted patents, the hammer bit includes an impact head at one end, for impacting the formation, and a drive shank at the other end, including an anvil end face. A pneumatic downhole hammer is connected at an upper end to the drill string or other components of the drilling assembly and is connected at a lower end to the drive shank of the hammer bit by a splined connection. As a result, rotation of the drill string rotates the hammer, which correspondingly rotates the hammer bit. Further, the hammer comprises an impact piston for engagement with the anvil end face of the hammer bit. Specifically, reciprocation of the impact piston of the hammer pneumatically results in the reciprocation of the hammer bit.
Thus, during drilling, pneumatic pressure fluid under high pressure is conducted via the drill string to the hammer for pneumatic reciprocation of the impact piston. Further, the drill string is employed for rotating the downhole hammer and bit during the drilling operation in a clockwise direction. As well, a compressive axial force is applied through the drill string to the drilling assembly such that a downward force may be maintained on the impact head of the hammer bit during drilling. More particularly, a proper weight-on-bit must be maintained in order to optimize the operation of the hammer and ensure proper transmission of impact energy from the hammer to the bit. Excess weight-on-bit may prevent the efficient operation of the hammer, while too light a weight-on-bit may allow the bit to oscillate off bottom and not transmit impact energy to the end of the borehole.
Alternately, as indicated, the hammer bit may be rotated independently without rotating the drilling assembly or the drill string. For example, in U.S. Pat. No. 5,305,837 issued Apr. 26, 1994 to Johns and U.S. Pat. No. 5,322,136 issued Jun. 21, 1994 to Bui et. al., the air hammer assembly impacts and simultaneously rotates a hammer bit independently of the drill string. Accordingly, the air hammer assembly is described as having specific application for controlled directional drilling.
More particularly, these air hammer assemblies also include a reciprocating piston. However, the kinetic energy of the reciprocating piston is employed to rotate the bit. The linear or axial motion of the piston is converted into rotational motion by using one or more helical grooves formed by the piston body. Further, to prevent the piston from oscillating in the rotary mode, an indexing clutch is provided to induce or permit rotation of the bit in one direction only. The upper portion of the hammer bit, which is normally splined, is replaced by a shaft which is slidably engaged with and keyed to a complimentary shaped female receptacle or bore formed by the lower portion of the piston. Therefore, the shaft of the hammer bit is at all times slidably engaged with the piston and is rotated thereby. Specifically, downward motion of the piston causes the bit to rotate in a clockwise direction. Upward motion of the piston rotates the inner race of the indexing clutch and prevents the bit from rotating in a counterclockwise direction.
U.S. Pat. No. 5,435,402 issued Jul. 25, 1995 to Ziegenfuss describes a further hammer bit which is also rotatable independently without rotating the drilling assembly or drill string. Specifically, a hammer bit member has an elongated body with a hollow area therein and at least one blade located in the hollow area. The blade or blades are adapted to receive pressurized air in order to impart a rotation to the hammer bit member, which has the hammer bit located at its distal end. A reciprocation mechanism, including a reciprocating piston, is connected to the other end of the hammer bit member in order to impart vertical reciprocation of the hammer bit member in response to the pressurized air. As a result, upon application of the air pressure, the hammer piston is activated to cause a reciprocal vertical motion, and at the same time, the air pressure impacts or impinges upon the blades to cause the hammer bit member to rotate.
Directional drilling may be defined as deflection of a borehole along a predetermined path in order to reach or intersect with a specific subterranean formation or target. The predetermined path typically includes a depth where initial deflection occurs and a schedule of desired deviation angles and directions over the remainder of the borehole. Thus, deflection is a change in the direction of the borehole from the current borehole path.
Deflection is measured as an amount of deviation of the borehole from the current borehole path and is expressed as a deviation angle or hole angle. Commonly, the initial borehole path is in a vertical direction. Thus, initial deflection often signifies a point at which the borehole has deflected off vertical. As a result, deviation is commonly expressed as an angle in degrees from vertical.
While directional drilling, in order to reach the desired subterranean formation or target, the deviation or hole angle may be increased or decreased as necessary. An increase in the deviation or hole angle is referred to as a build angle and produces a build rate and a build section of the borehole. A decrease in the deviation or hole angle is referred to as a drop angle and produces a drop rate and a drop section of the borehole.
When drilling an inclined hole, the forces which act upon the drilling bit, and which affect the resulting direction of the drilled borehole, may be resolved into three components: axial load, pendulum force and formation reaction. The axial load is a compressive axial force and is typically supplied by the weight of the drilling assembly and attached drill string. The pendulum force is a lateral force which results from the weight of the drilling assembly between the drilling bit and a first or lowermost point of contact of the wall of the borehole with the drilling assembly. The pendulum force is the tendency of the unsupported length of the drilling assembly to swing over against the low side of the borehole because of gravity. The formation reaction is the reaction of the formation to the axial load and pendulum load. Commonly, where the hole angle is desired to be reduced, or a drop angle is desired, a pendulum technique may be employed which utilizes the pendulum force and gravity to bring the borehole back towards vertical.
Further, when directional drilling, by either rotary drilling or sliding drilling, the use of a stabilizer in the bottom hole assembly can assist in controlling the direction of the borehole. More particularly, the primary purpose of using stabilizers in the bottom hole assembly is to stabilize the drilling bit that is attached to the distal end of the bottom hole assembly so that it rotates properly on its axis. A secondary purpose of using stabilizers in the bottom hole assembly is to assist in steering the drill string so that the direction of the borehole can be controlled. For example, properly positioned stabilizers can assist either in increasing or decreasing the deflection angle of the borehole either by supporting the drill string near the drilling bit or by not supporting the drill string near the drilling bit.
Conventional stabilizers can be divided into two broad categories. The first category includes rotating blade stabilizers which are incorporated into the drill string and either rotate or slide with the drill string. The second category includes non-rotating sleeve stabilizers which typically comprise a ribbed sleeve rotatably mounted on a mandrel so that during drilling operations, the sleeve does not rotate while the mandrel rotates or slides with the drill string. Rotating blade type stabilizers are far more common and versatile than non-rotating sleeve stabilizers, which tend to be used primarily in hard formations and where only mild wellbore deflections are experienced.
The specific design of a bottom hole assembly requires consideration of where, what type and how many stabilizers should be incorporated into the drill string. In addition, the specific gauge of the stabilizer must be taken into consideration. Further, since it is usually necessary to adjust the direction of the borehole frequently during directional drilling, the desired type, number and location of stabilizers in the drill string may vary from time to time during drilling. As a result, when directional drilling, the entire drill string may need to be removed from the borehole in order to add or remove such conventional stabilizers to or from the drill string when a change in direction of the borehole is desired. Both adjustment of the stabilizers and the bottom hole assemblies is frequently required. This is extremely costly and time consuming.
As a result, various methods and techniques have been developed which attempt to provide a manner of controlling the direction of the resulting borehole while drilling without the need to remove the drilling assembly from the borehole. However, none of these methods or techniques are completely satisfactory.
For example, U.S. Pat. No. Re. 33,751 reissued Nov. 26, 1991 to Geczy utilizes a plurality of stabilizers to control the direction of the resulting borehole. More particularly, Geczy provides an overall system approach to design the hardware for drilling according to a specific desired well plan. Specifically, the bend angle of a bent housing, the diameter of a plurality of stabilizers, the placement of the stabilizers with respect to the drill bit and the weight on bit must all be selected and predetermined on the basis of the specific desired well plan. In other words, the bottom hole assembly must be uniquely tailored for each proposed well plan. As well, the system uses at least three, and preferably four, concentric stabilizers which are precisely located along the drill string.
Utilizing the specialized system of Geczy, direction changes are controlled by controlling the rotation of the drill string. For curved path drilling, only the downhole motor is rotated, causing the borehole to travel along the curve determined by the bend angle in the bent housing and the diameter and location of the concentric stabilizers. When straight hole drilling is required, both the downhole motor and the entire string are rotated.
As a result, there remains a need in the industry for a downhole drilling assembly and a drilling method for use in directional drilling, which provide the ability to control the direction of the resulting borehole. More particularly, there is a need for a downhole drilling assembly and a drilling method for use in directional drilling, which provide the ability to control the direction of the resulting borehole, when rotary drilling or sliding drilling using a reciprocating hammer bit. Further, there is a need for such a drilling assembly and drilling method capable of selectively producing an increase in the deviation angle of the borehole or producing a build angle or build section for building the borehole. Finally, there is a need for the drilling assembly and drilling method to also be capable of selectively producing a decrease in the deviation angle of the borehole or producing a drop angle or drop section for dropping the borehole.